This section is intended to introduce the reader to aspects of art that may be related to various aspects of the present invention or present solution, which are described and/or claimed below. This discussion is believed to be helpful in providing the reader with background information to facilitate a better understanding of the various aspects of the present invention. Accordingly, it should be understood that these statements are to be read in this light, and not as admissions of prior art.
During the construction of a well, particularly oil and gas wells, tubular pipe, which is also known as a joint, conductor pipe, conductor casing, casing, and/or tubing, are joined together to create a “string”, which is a long section of connected tubular pipe that is lowered into a wellbore and eventually serves as the foundation and production conduit for the well. The most common and traditional method for placing a tubular string into the earth involves drilling and creating a borehole in the earth and placing and cementing the tubular in the borehole to the earth. Other traditionally prevailing methods for placing a tubular string in the earth include jetting and piling, although these methods are typically only for the first and uppermost tubular string in a well. This first and uppermost tubular string is also called the conductor string, conductor casing string, conductor casing, conductor pipe or drive pipe. This section of the well is known as the top-hole section. Specifically referring to the top-hole section, the conductor string plays a very critical role in the further drilling, construction, foundation, and short and long term integrity of the well, in that along with serving as the initial foundation, permanent structure, and outermost connection to the wellhead and/or blowout preventer of the well, it must bear significant loads during each and every phase in the life of the well, which includes drilling, construction, and the production operation.
These loads can include the weight of the conductor string itself, drilling and production risers, wellhead, blowout preventer, casing strings, platform structure, and other various drilling and production operational equipment. When placing the conductor string into the earth using the aforementioned traditionally prevailing methods, conductor strings generally appear to provide adequate load-bearing capacity for the aforementioned operational equipment, although from time to time it is also common even in these traditional methods for conductor strings to sink after they are initially set, in some cases occurring immediately to during the drilling and well construction process up to decades later during production or even abandonment, always due to inadequate load-bearing capacity. As drilling depths increase, more complex and heavier operational equipment, especially wellheads, blowout preventers, and casing strings are being employed. Also, referring to well design, with the proliferation of directional drilling, non-vertical, extended reach, horizontal, slant and or angled wells are becoming more common requiring an early or shallow drilling bit exit from the top-hole conductor string bottom or shoe. This early or shallow drilling bit exit is required in order to begin to build angle in the subsequent borehole for the eventual reach of the intended target, which could only be reached due to this early angle build due to a maximum allowable inclination, bend or slant due to equipment limitations. Specifically referring to the early or shallow drilling bit exit from the top-hole conductor string bottom or shoe, this may limit the conductor string total length and depth in the earth, as a predetermined top-hole conductor string setting depth, total depth, or shoe point becomes a priority and takes precedence over a deeper more adequate setting depth to ensure proper load-bearing capacity.
Also, in some instances, unforeseen and/or unique circumstances involving formation, formation plasticity, formation set-up, cement job, cement composition, cement bond, conductor pipe, conductor pipe bond, connectors, assemblies, and other down-hole variables may cause inadequate load-bearing capacity in a conductor string. For example, formation set-up is a direct function of time in that the greater the time a tubular pipe or string remains in undisturbed contact with the earth, the greater the load-bearing capacity of said tubular string. This varies depending on multiple factors, mainly formation plasticity, but typical well construction procedures do not allow time for a tubular pipe or string remaining in undisturbed contact with the earth after placement mainly due to the economics of the practice. As a result down time or non-productive time costs associated with the practice would be realized in such a case, as further drilling operations must be halted to keep the tubular pipe or string in undisturbed contact with the earth. These costs can include but are not limited to drilling rig day rates, other daily spread costs and opportunity costs associated with late delivery of well production. An additional outlying reason includes the impossibility to calculate set-up effects on load-bearing capacity due to multiple unique factors associated with each and every well design and the area geology, which can vary even on wells drilled on the same exact platform only feet apart. Consequently, there exists a lack of expertise in the practice.
Hence, what is needed is an apparatus, system and/or method for increasing the load-bearing capacity of a tubular pipe or string that can be quickly deployed and is cost effective.